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  • 1. ENERGY. BB&T Commercial & Industrial ConferenceSTRENGTH. New York City April 7, 2011OPPORTUNITY. 1
  • 2. Forward Looking StatementsCertain statements contained herein that are not descriptions of historical facts are "forward-looking" statements within the meaningof federal securities laws. Because such statements include risks, uncertainties and contingencies, actual results may differ materiallyfrom those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are notlimited to, the following: the volatility of commodity prices for natural gas, NGLs and coal; our ability to access external sources ofcapital; any impairment write-downs of our assets; the relationship between natural gas, NGL and coal prices; the projected demandfor and supply of natural gas, NGLs and coal; competition among producers in the coal industry generally and among natural gasmidstream companies; the extent to which the amount and quality of actual production of our coal differs from estimatedrecoverable coal reserves; our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution toour general partner and our unitholders; the experience and financial condition of our coal lessees and natural gas midstreamcustomers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gasmidstream businesses; our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supplyand connections to third-party pipelines on satisfactory terms; our ability to retain existing or acquire new natural gas midstreamcustomers and coal lessees; the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reservesand obtain favorable contracts for such production; the occurrence of unusual weather or operating conditions including forcemajeure events; delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects andnew processing plants in our natural gas midstream business; environmental risks affecting the mining of coal reserves or theproduction, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us or our lessees;hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental,health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertaintiesrelating to the outcome of current and future litigation regarding mine permitting; risks and uncertainties relating to generaldomestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions(including the impact of potential terrorist attacks); and other risks set forth in our Annual Report on Form 10-K for the fiscal yearended December 31, 2010.Additional information concerning these and other factors can be found in our press releases and public periodic filings with theSecurities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2010. Many of thefactors that will determine our future results are beyond the ability of management to control or predict. Readers should not placeundue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake noobligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a resultof new information, future events or otherwise. BB&T Conference 4/7/2011 2
  • 3. ENERGY. Overview & Key Investment HighlightsSTRENGTH.OPPORTUNITY. 3
  • 4. Key Investment Highlights Diversified Portfolio of Coal Reserves and Midstream Assets Simplified Capital Structure to Enhance Growth Potential Stable and Predictable Coal Royalty Business Midstream Business with Excellent Organic Growth Opportunities Stable Cash Flows and Distribution Coverage Strong, Simple Balance Sheet with Ample Liquidity Well Positioned to Capitalize on Partnership Momentum & Industry TrendsBB&T Conference 4/7/2011 4
  • 5. Simplified Partnership StructurePVR / PVG merger: Public Simplified structure Unitholders 71.0 Million Common Units – Non-economic GP interest Elimination of incentive distribution rights 100% LP interest 100% LLC interest – No “high splits” Penn Penn Virginia Reduced cost of capital Resource Partners, L.P. Virginia Resource (NYSE: PVR) GP, LLC Reduced corporate costs Enhanced investor and market profile Non-economic GP interest – Increased float and trading liquidity PVR Finco LLC Improved governance – Unitholders gain right to elect all directors PVR Coal PVR Midstream Operations Operations BB&T Conference 4/7/2011 5
  • 6. Business Segments Coal & Natural Resource Management Natural Gas Midstream ~ 61% of 2010 EBITDA (1) ~ 39% of 2010 EBITDA (1)  Coal royalty business, not coal mining  Traditional gathering and processing business  Managed coal properties since 1882  Assets are located in attractive natural gas basins with long-lived reserves  Controls approximately 800 MM tons of high quality coal reserves (23 year R/P ratio) (2) – 4,263 miles of pipelines  Long-term leases with experienced operators – 6 processing facilities  Ancillary businesses include coal services, timber – 400 MMcfd of capacity and gas royalties  Average throughput volume 355 MMcfd in 2010  Cash flows naturally hedged with multi-year contracts between producers and end users  Attractive fee-based organic growth opportunities in Marcellus Shale 2010 EBITDA (1): $201.8 million 2011 EBITDA (1) Guidance: $230.0 million(1) EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of EBITDA to net income and cash flow from operations.(2) Does not include approximately 102 million tons of coal reserves and resources acquired from Begley Properties in January 2011 BB&T Conference 4/7/2011 6
  • 7. Strategically Located Assets Natural Gas Midstream Coal & Natural Resource Management Gathering systems located in major gas basins  Coal reserves located in major supply basins Oklahoma and Texas reserves include plays in  Access to major coal hauling railroads and Granite Wash and liquids-rich production inland waterways Significant fee-based growth potential from  Close proximity to power generation facilities Marcellus Shale Marcellus Powder River Basin Northern & Central San Juan Appalachia Basin Illinois Basin Texas & Oklahoma BB&T Conference 4/7/2011 7
  • 8. Coal Royalty Business: Stable Cash Flow Coal Royalty vs. Coal Operator Historical Coal Prices vs. Coal Royalty Revenue Quarterly Coal Royalty Revenue Coal royalty – not a coal mining operation $140 Central Appalachia $40 Illinois Basin $120 $35 Quarterly Revenue ($Millions) Characteristic Coal Royalty Coal Operator Spot Coal Prices ($/Ton) $100 $30 Operating Margins High Variable $25 $80 $20 Cash Flow Stability High Variable $60 $15 Reinvestment $40 $10 Medium High Requirements $20 $5 Social Costs (e.g. Low High $0 $0 benefits, black lung) Jul-07 Jul-08 Jul-09 Jul-10 Apr-07 Oct-07 Apr-08 Oct-08 Apr-09 Oct-09 Apr-10 Oct-10 Jan-07 Jan-08 Jan-09 Jan-10 Reclamation Exposure Low High Majority of our royalty payments (~80%) are based on the higher of a percentage of the gross sales price or a fixed price per ton Contracts with our lessees are long-term, with an average life of 10 – 15 years Substantially all leases require minimum payments even if no mining activities are ongoing No direct exposure to mine operating costs and risks or reclamation costs Our lessees generally sell their coal to end users under long-term fixed-price contracts BB&T Conference 4/7/2011 8
  • 9. Midstream Business: Managed Growth Management focused on continued reduction of Volumes by Contract commodity price risk by: – Pursuing system expansions backed by fee- based contracts Fee- Based Fee- Based – Converting a portion of the existing keep- 14% Percent of 22% Proceeds Percent of whole contracts to fee-based or POP Keep- Proceeds 34% Keep- Whole 62% Whole – Acquiring fee-based businesses 52% 16% Hedging remaining commodity-sensitive volumes – Target 50% - 60% for two years out Midstream Throughput Volume Significant organic fee-based growth potential – Primarily in Marcellus Shale Many gas purchase / keep-whole contracts contain a processing fee floor BB&T Conference 4/7/2011 9
  • 10. Conservatively Financed, Low-Risk Growth Historical growth fueled by relatively strong margins, organic growth opportunities and acquisitions – Recent organic growth largely in midstream – Recent acquisition growth primarily coal and natural resource assets Completed acquisitions in excess of $1.0 billion since IPO in 2001(2) – No single acquisition > $200 million Coal reserves have increased by 63% since 2001; Annual production volume has increased by 125% Midstream throughput volumes have increased over 100% since 2006 Raised approximately $360 million of equity since IPO in 2001 EBITDA(1) Growth with Conservative Leverage(1) EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of EBITDA to net income and cash flow from operations.(2) Does not include approximately $97 million for coal properties acquired from Begley Properties in January 2011 BB&T Conference 4/7/2011 10
  • 11. ENERGY. Coal & Natural ResourceSTRENGTH. ManagementOPPORTUNITY. 11
  • 12. Coal: Attractive Industry FundamentalsEIA(1) forecasts that coal: U.S. Energy Supply Composition By Primary Source Usage will continue to increase for next 25 years Will continue to be the dominant fuel for electric power generation in the U.S. Will retain its cost advantage as the cheapest energy source U.S. Electrical Generation By Fuel Type Energy Prices (2) (1) Annual Energy Outlook 2011 (March 2011), Energy Information Administration (EIA) (2) Prices paid for energy by Electric Generation Sector as reported by EIA BB&T Conference 4/7/2011 12
  • 13. Coal & Natural Resource Management Proven / 2010 Lease R/P Probable Region Production Ratio Reserves (MM tons) (years) (MM tons) Northern 4.0 29.7 7.4 Appalachia Central 18.2 583.5 32.1 Appalachia (1) Illinois Basin 4.2 161.2 38.4 San Juan 8.1 29.3 3.6 Basin Total (1) 34.5 803.7 23.3(1) Does not include approximately 102 million tons of coal reserves and resources in Central Appalachia Region acquired from Begley Properties on January 25, 2011 BB&T Conference 4/7/2011 13
  • 14. Coal – Operations (1) Royalties by Region – 2010 Reserves by Region – 2010 Reserves by Type – 2010 Changes in Coal Reserves: 2002 – 2010 Coal Production(1) Statistics as of 12/31/2010 and do not include approximately 102 million tons of coal reserves and resources acquired from Begley Properties in January 2011 BB&T Conference 4/7/2011 14
  • 15. Primary Coal Basins Central Appalachia (72% of Reserves) (1) Illinois Basin (20% of Reserves) Consists of a combination of surface and  Comprised of properties in southern Illinois and underground mines located in KY, VA and WV western Kentucky Coal is higher quality, lower sulfur  Acquired 169 MM tons of reserves in the Illinois Proximity to East Coast ports make these mines an Basin beginning in 2005 ideal source of exports  The installation of scrubbers by Eastern and Acquired ~102 million additional tons of coal Midwestern utilities has increased demand for the reserves and resources from Begley Properties in high sulfur coal in the Illinois Basin January 2011 (1) 2010 statistics do not include Begley assets acquired in January 2011 BB&T Conference 4/7/2011 15
  • 16. Primary Coal Basins Northern Appalachia (4% of Reserves) San Juan Basin (4% of Reserves) Northern Appalachia holdings consist of the  Our Lee Ranch property is located in the San Juan Federal and Upshur properties Basin of northwestern New Mexico and contains only surface coal mines Reserves are 100% owned and 98% have been leased to operators Acquired 10 million tons of Pittsburgh seam reserves in July 2010 BB&T Conference 4/7/2011 16
  • 17. Services, Timber & Oil & Gas Royalties Services Timber Oil & Gas Royalties ~ 5% of Coal & NRM Revenue (1) ~ 4% of Coal & NRM Revenue (1) ~ 2% of Coal & NRM Revenue (1) Fees charged to lessees for  Approximately 243,000 acres  Approximately 6.3 Bcfe of use of coal preparation and of forestland in Kentucky, proved oil and gas reserves in loading facilities Virginia and West Virginia eastern Kentucky and southwestern Virginia Fee-based revenues  Premium quality hardwood primarily used for furniture Predictable cash flows(1) 2010 Coal & Natural Resource Management segment revenue BB&T Conference 4/7/2011 17
  • 18. ENERGY. Natural GasSTRENGTH. MidstreamOPPORTUNITY. 18
  • 19. Natural Gas Midstream Overview Gathering Processing 2010 Crescent Marcellus System Pipeline Capacity Volume Thunder Creek (Miles) (MMcfd) (MMcfd) Panhandle 1,817 260 222 Marcellus 3 N/A 10 Crescent 1,705 40 22 Arkoma 78 N/A 11 North 136 N/A 16 Texas Panhandle Crossroads 8 80 67 Hamlin Arkoma Hamlin 517 20 8 Crossroads Thunder 535 N/A 373 North Texas Creek (25% JV) Total (1) 4,263 400 355(1) Totals do not include Thunder Creek. Pipeline miles and volume totals may not foot due to individual system rounding. BB&T Conference 4/7/2011 19
  • 20. Well Positioned Asset Base Our assets are well positioned to benefit from increasing activity in emerging resource plays: – Marcellus Shale – Granite Wash – Haynesville Shale / Horizontal Cotton Valley Attractive processing economics are expected to persist Oil-to-Natural Gas Price Ratio Lower 48 State On-Shore Gas Production 25 Conventional Shale Gas Coalbed M ethane Oil Associated 25 Trillion Cubic Feet 20 20 Ratio $/Bbl / $MMBtu 15 15 10 10 Shale gas drives future 5 production growth 5 0 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 0 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 Sources: Energy Information Agency, Baker Hughes, Bloomberg BB&T Conference 4/7/2011 20
  • 21. Panhandle Systems Overview & Statistics Gathering systems in the Anadarko Basin of Texas and Oklahoma 1,817 miles of pipeline Comprised of a number of major gathering systems and 30 compressor stations 3 Processing Plants with 260 MMcfd of total inlet capacity – Beaver: 100 MMcfd – Spearman: 100 MMcfd (Expanded 7/09) – Sweetwater: 60 MMcfd (Acquired 7/09) Approximately 200 producers pursuant to >300 contracts Positioned to capitalize on the development of the Granite Wash SWEETWATER PLANT BB&T Conference 4/7/2011 21
  • 22. Marcellus Systems Overview PVR provides gathering, compression & related services 100% fee-based: – Firm reservation charges provide a floor on returns – Additional volumetric fees based upon actual deliveries 2010 Capital Expenditure: $49.5 Million Anticipated 2011 Capital: $120 MillionBB&T Conference 4/7/2011 22
  • 23. Marcellus Systems Lycoming System Wyoming System First large-diameter gathering system in north-central PA Marcellus  Began service June 2010 fairway  3 miles of 12-inch pipeline in service (as of 30-inch pipeline 12/31/2010) 850 MMcfd capacity  Currently constructing system extension to 1st phase began service 2/16/2011 service additional local producers Range Resources is anchor customer pursuant to AMI dedicating 75,000 acres Phase II of system expected in service Q3/Q4 2011 Completed or Under Future Expansion Construction Phase III Phase I Phase II BB&T Conference 4/7/2011 23
  • 24. Natural Gas Midstream – Other Systems Crossroads Crescent Hamlin Located in the southeast portion of  Gathering system in Oklahoma’s  Gathering system stretching over eight Harrison County, Texas Sooner Trend West Central Texas counties Anchored by a long-term commitment  Consists of 1,705 miles of pipeline and  Consists of 517 miles of pipeline and 8 under a fee-based arrangement 14 related compressor stations related compressor stations 80 MMcfd of inlet capacity  Processing plant  Hamlin processing plant located in Centered around 5 major producers – NGL recovery unit Fisher County, Texas – 40 MMcfd capacity – 20 MMcfd capacity Positioned for growth from Haynesville Shale  Wells are generally low-volume and long-lived with large NGL quantities North Texas Arkoma Thunder Creek Gas Services Gas gathering and transportation  Consists of three separate stand-alone  Located in Wyoming’s Powder River assets in the Barnett Shale play in the gathering systems in southeastern Basin Fort Worth Basin Oklahoma’s Arkoma Basin  25% JV interest – 136 miles of gathering pipeline – Two systems are 100% owned, – Devon Energy owns the other 75% – Approximately 240,000 dedicated third system is 49% owned interest acres – Average 2009 throughput volume  100% fee-based 100% fee-based revenues of 11 MMcfd  Average 2010 throughput volume of 373 MMcfd BB&T Conference 4/7/2011 24
  • 25. ENERGY. Financial OverviewSTRENGTH.OPPORTUNITY. 25
  • 26. Strong Financial Position Strong, simple balance sheet – Bank debt, senior notes and common units – No debt maturity until 2015 – Expect to maintain or improve BB-/Ba3 corporate ratings Well structured bank credit facility – $850 million revolving credit facility – 19 banks with no bank holding more than 8.2% of total – Available liquidity on revolver in excess of $320 million (1) Maintain conservative and flexible capital structure – Fund organic growth and acquisitions with cash and balanced mix of debt and equity – Target a long-term Debt/EBITDA of 3.5x (1) Total available capacity as of 2/11/2011BB&T Conference 4/7/2011 26
  • 27. Financial Overview Prudently managed balance sheet, Annual EBITDA (1) cash flows and distributions Target distribution coverage of $250 1.05x – 1.00x after deducting $200 replacement capital $ Millions $150 Future debt and equity financings $100 for acquisitions and internal growth $50 will target long-term net debt / $0 EBITDA ratio of ≤ 3.5x 2006 2007 2008 2009 2010 Distributable Cash Flow(2) vs. Distributions Debt / EBITDA (1) $160 DCF 4.0x $140 Distributions $120 3.0x$ Millions $100 $80 2.0x $60 $40 1.0x $20 $0 0.0x 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 (1) Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to Operating Income. (2) Distributable Cash Flow is a non-GAAP financial measure. See Appendix for a reconciliation of Distributable Cash Flow to Net Income. BB&T Conference 4/7/2011 27
  • 28. Conservative Capitalization Balance Sheet as of December 31, 2010 Revolving Credit Facility $ 408.0 8.25% Senior Notes due 2018 300.0 Total Debt $ 708.0 Partners Capital 428.5 Total Capitalization $ 1,136.5 EBITDA (1) 201.8 Debt / EBITDA 3.5x Debt / Capitalization 62% Revolver Capacity (2) $ 850.0 Revolver Availability (3) $ 440.4 (1) EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of EBITDA to operating income and cash flows from operations (2) On August 13, 2010, PVR closed on an amended 5 year credit facility of $850 million (3) Revolver availability includes adjustment for $1.6 million in letters of credit Conservative Pro Forma Leverage with Strong Liquidity ProfileBB&T Conference 4/7/2011 28
  • 29. Key Investment Highlights  Diversified Portfolio of Coal Reserves and Midstream Assets  Simplified Capital Structure to Enhance Growth Potential  Stable and Predictable Coal Royalty Business  Midstream Business with Excellent Organic Growth Opportunities  Stable Cash Flows and Distribution Coverage  Strong, Simple Balance Sheet with Ample Liquidity Well Positioned to Capitalize on Partnership Momentum & Industry TrendsBB&T Conference 4/7/2011 29
  • 30. ENERGY. AppendixSTRENGTH.OPPORTUNITY. 30
  • 31. Derivative Hedging Strategy  PVR is long NGLs and short natural gas  Active hedge strategy to mitigate commodity price risk – Exposed to “frac spread” risk through wellhead purchase contract and to direct commodity price risk through percent-of-proceeds contacts  Current and future hedges (1) – 2011 hedges are 55% of current price-sensitive volumes – 2012 hedges are 32% of current price-sensitive volumes – Target hedging 50-60% of price sensitive exposure out 2 years  Sensitivity to commodity price changes is expected to decrease as a result of increasing fixed- fee volumes from the Marcellus Shale, Thunder Creek and Crossroads  Hedging parameters established by Board of Directors  Hedging execution overseen directly by executive management(1) Base upon hedging positions and volumes as of 12/31/2010 BB&T Conference 4/7/2011 31
  • 32. Distributable Cash Flow Reconciliation PVR - Historical Distributable Cash Flow Summary ($ in millions) Guidance Year Ended December 31, 2011 2010 2009 2008 2007 2006 2005 Net Income $ 90.0 $ 68.5 $ 65.2 $ 104.5 $ 56.6 $ 73.9 $ 51.2 DD&A 84.0 75.9 70.2 58.2 41.5 37.5 30.6 Impairments - - 1.5 31.8 - - - Total derivative losses (gains) 11.0 23.6 22.7 (11.4) 50.2 13.2 13.0 Cash settlements of derivatives (10.0) (10.1) 3.0 (38.5) (17.8) (19.4) (4.8) Equity earnings from JVs, net of distributions 6.0 3.3 (2.5) (0.2) (0.3) 1.3 1.3 Other - - - - - 4.6 - Maintenance CAPEX (14.0) (15.3) (8.4) (14.5) (9.8) (9.5) (4.6) (1) Distributable Cash Flow As Reported 167.0 145.8 151.7 129.9 120.5 101.6 86.7 Replacement Capital (27.0) Distributable Cash Flow 140.0(1) Distributable cash flow represents net income plus depreciation, depletion and amortization expenses, plus impairments, plus (minus) derivative losses (gains) included in other income, plus (minus) cash received (paid) for derivative settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures. Distributable cash flow is a significant liquidity metric which is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners. Distributable cash flow is also the quantitative standard used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.Note: Totals may not foot due to rounding BB&T Conference 4/7/2011 32
  • 33. Reconciliation of EBITDA PVR - Historical EBITDA Summary ($ in millions) Guidance Year Ended December 31, 2011 2010 2009 2008 2007 2006 Reconciliation of GAAP "Operating Income" to Non-GAAP "EBITDA" Operating Income 146.0 125.9 108.3 115.2 117.7 102.8 Depreciation, depletion & amortization 84.0 75.9 70.2 58.2 41.5 37.5 Impairments - - 1.5 31.8 - - (1) EBITDA 230.0 201.8 180.0 205.2 159.2 140.3 (1) EBITDA, or earnings before interest, tax and depreciation, depletion and amortization ("DD&A) represents operating income plus DD&A, plus impairments. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the coal and natural gas midstream industries. We use this information for comparative purposes within the industry. EBITDA is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.BB&T Conference 4/7/2011 33